Natural Gas and Oil Property Divestitures

During the Current Period and the Prior Period, excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $240 million and $815 million, respectively, related to divestitures of noncore natural gas and oil properties.

Under full cost accounting rules, we have accounted for the sale of natural gas and oil properties as an adjustment to capitalized costs, with no recognition of gain or loss as the sales have not involved a significant change in proved reserves or significantly altered the relationship between costs and proved reserves.

Joint Ventures

As of June 30, 2014, we had entered into eight significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in eight different resource plays and received cash of $8.0 billion and commitments by our counterparties to pay our share of future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. The carries paid by a joint venture partner are for a specified percentage of our drilling and completion costs. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. We bill our joint venture partners for their drilling carries at the same time we bill them and other joint working interest owners for their share of drilling costs. For accounting purposes, initial cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. The transactions are detailed below.



Primary Play	Joint Venture Partner^(a)	Joint Venture Date	Interest Sold	Initial Proceeds^(b)			Total Drilling Carries			Total Initial Proceeds and Drilling Carries		Drilling Carries Remaining^(c)
				($ in millions)
Mississippi Lime	Sinopec	June 2013	50.0%	$	949	^(d)	$	—		$	949	$	—
Utica	TOT	December 2011	25.0%	610			1,422		^(e)	2,032		347
Niobrara	CNOOC	February 2011	33.3%	570			697		^(f)	1,267		26
Eagle Ford	CNOOC	November 2010	33.3%	1,120			1,080			2,200		—
Barnett	TOT	January 2010	25.0%	800			1,403			2,203		—
Marcellus	STO	November 2008	32.5%	1,250			2,125			3,375		—
Fayetteville	BP	September 2008	25.0%	1,100			800			1,900		—
Haynesville & Bossier	FCX	July 2008	20.0%	1,650			1,508			3,158		—
				$	8,049		$	9,035		$	17,084	$	373

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(a)	Joint venture partners are Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Freeport-McMoRan Copper & Gold (FCX), formerly known as Plains Exploration & Production Company.


(b)	Excludes closing and post-closing adjustments.


(c)	As of June 30, 2014.


(d)	Excludes $71 million of net proceeds (or 7% of the total transaction) expected to be received pursuant to certain post-closing adjustments and approximately $90 million received at closing for closing adjustments.


(e)	The Utica drilling carry covers 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. We expect to fully utilize this drilling carry commitment prior to expiration.


(f)	The Niobrara drilling carry covers 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize this drilling carry commitment prior to expiration.

During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $357 million and $436 million, respectively, in drilling and completion carries paid by our joint venture partners.

During the Current Period and the Prior Period, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Haynesville, Eagle Ford, Mid-Continent and Niobrara Shale plays to our joint venture partners for approximately $8 million and $39 million, respectively.

Volumetric Production Payments

From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. A VPP is a limited-term overriding royalty interest in natural gas and oil reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. For all of our VPP transactions, we have novated hedges to each of the respective VPP buyers and such hedges covered all VPP volumes sold. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.

As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to such interests, which we include as a component of production expenses and production taxes in our condensed consolidated statements of operations in the periods such costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which such production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.

For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of natural gas and oil properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

Our outstanding VPPs consist of the following:



					Volume Sold
VPP #	Date of VPP	Location	Proceeds		Natural Gas	Oil	NGL	Total
			($ in millions)		(bcf)	(mmbbl)	(mmbbl)	(bcfe)
10	March 2012	Anadarko Basin Granite Wash	$	744	87	3.0	9.2	160
9	May 2011	Mid-Continent	853		138	1.7	4.8	177
8	September 2010	Barnett Shale	1,150		390	—	—	390
6	February 2010	East Texas and NW Louisiana	180		44	0.3	—	46
5	August 2009	South Texas	370		67	0.2	—	68
4	December 2008	Anadarko and Arkoma Basins	412		95	0.5	—	98
3	August 2008	Anadarko Basin	600		93	—	—	93
2	May 2008	Texas, Oklahoma and Kansas	622		94	—	—	94
1	December 2007	Kentucky and West Virginia	1,100		208	—	—	208
			$	6,031	1,216	5.7	14.0	1,334

The volumes produced on behalf of our VPP buyers for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows:



	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
VPP #	Natural Gas	Oil	NGL	Total	Natural Gas	Oil	NGL	Total
	(bcf)	(mbbl)	(mbbl)	(bcfe)	(bcf)	(mbbl)	(mbbl)	(bcfe)
10	2.7	103.0	329.9	5.3	3.4	141.0	379.0	6.5
9	3.9	47.5	103.9	4.8	4.3	54.2	115.4	5.3
8	15.2	—	—	15.2	17.3	—	—	17.3
6	1.1	6.0	—	1.1	1.2	6.0	—	1.2
5	1.7	6.0	—	1.7	1.9	6.2	—	1.9
4	2.3	12.2	—	2.3	2.6	13.8	—	2.7
3	1.8	—	—	1.8	2.0	—	—	2.0
2	1.6	—	—	1.6	2.6	—	—	2.6
1	3.4	—	—	3.4	3.6	—	—	3.6
	33.7	174.7	433.8	37.2	38.9	221.2	494.4	43.1



	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
VPP #	Natural Gas	Oil	NGL	Total	Natural Gas	Oil	NGL	Total
	(bcf)	(mbbl)	(mbbl)	(bcfe)	(bcf)	(mbbl)	(mbbl)	(bcfe)
10	5.5	212.0	675.1	10.8	7.0	295.0	786.7	13.5
9	7.9	96.5	210.4	9.7	8.7	110.4	234.2	10.8
8	30.9	—	—	30.9	35.3	—	—	35.3
6	2.2	12.0	—	2.3	2.4	12.0	—	2.4
5	3.4	12.3	—	3.5	3.9	12.2	—	3.9
4	4.6	24.6	—	4.7	5.2	28.0	—	5.4
3	3.7	—	—	3.7	4.1	—	—	4.1
2	4.0	—	—	4.0	5.3	—	—	5.3
1	7.0	—	—	7.0	7.4	—	—	7.4
	69.2	357.4	885.5	76.6	79.3	457.6	1,020.9	88.1

The volumes remaining to be delivered on behalf of our VPP buyers as of June 30, 2014 were as follows:



		Volume Remaining as of June 30, 2014
VPP #	Term Remaining	Natural Gas	Oil	NGL	Total
	(in months)	(bcf)	(mmbbl)	(mmbbl)	(bcfe)
10	92	43.1	1.5	5.3	83.9
9	80	80.8	0.9	2.1	99.2
8	14	65.7	—	—	65.7
6	67	19.2	0.1	—	20.0
5	31	13.5	—	—	13.8
4	30	19.7	0.1	—	20.3
3	61	27.4	—	—	27.4
2	58	16.0	—	—	16.0
1	102	98.4	—	—	98.4
		383.8	2.6	7.4	444.7